Field of the Disclosure
The present disclosure concerns a sleeve valve and an apparatus using the sleeve valve for injecting a fluid into a geological formation.
Prior and Related Art
For ease of understanding, this disclosure is described with respect to production of hydrocarbons, in particular hydraulic re-fracturing. However, the scope of the present disclosure may be used without modification in related technical fields, such as geothermal applications.
As used herein, a ‘borehole’ is an uncased hole drilled through several layers of rock in a geological formation onshore or offshore. The drilling is performed by rotating a drill bit at the end of a hollow drill string, i.e. a jointed pipe or coiled tubing. Several methods for rotating the entire drill string are well known and in use. Alternatively, a mud motor may rotate the drill bit. As used herein, a mud motor is any device caused to rotate by expelling a fluid, not necessarily drilling mud, through tangential openings.
A ‘wellbore’ is a borehole with a steel casing and/or liner cemented to the formation along all or part of its length, and a ‘well’ is a wellbore with any equipment required for operation. For simplicity, any steel tubing cemented to the formation is termed ‘casing’ in the following. After cementing, the casing is perforated at one or more zones to allow, for example, hydrocarbons to enter or water with or without additives to exit. A zone generally corresponds to a layer of porous rock, for example, shale, sandstone or limestone containing hydrocarbons.
Hydraulic fracturing and stimulation may improve the flow of hydrocarbons from the zone. These techniques may be employed before production starts, and may be repeated one or more times during the lifetime of a production well.
One or more injection wells may be located at a distance from the production well. An injection well usually has a design similar to that of a production well, and sometimes the injection well is an old production well. The process of injecting a fluid, e.g. water or liquid CO2, through an injection well to maintain the pressure in a zone is known as ‘enhanced oil recovery’ or EOR.
Hydraulic fracturing and re-fracturing, stimulation and re-stimulation as well as EOR are examples of injection of fluid into a formation, i.e. at a pressure exceeding the ambient pressure in the formation. Other examples are injection of flue gas into an aquifer and, as mentioned above, geothermal applications.
Regardless of application, the injection of fluid comprises the steps of inserting a string into a wellbore, spanning the zone by packers, opening a sleeve valve and injecting the fluid. The fluid is supplied through a central bore within the string through radial openings in the valve. The packers uphole and downhole from the radial openings, e.g. at both ends of the perforated length of casing, must seal against the wellbore wall when an injection pressure is applied. A packer sealing in this manner is ‘set’.
A typical packer comprises an elastic element that expands radially when compressed axially, and is set when the elastic element engages a wellbore wall, i.e. the rock in an uncased borehole or the casing in a cased part of the wellbore. Several methods for contracting packer elements axially are known in the art. For example, rotating a lead screw can cause one or more sleeves to move axially with respect to each other on a guiding mandrel. In another example, an area exposed to a predetermined activation pressure causes a force required to set the packer. In some packers, the force provided by the activation pressure merely activates a release mechanism, and the force required to set the packer is provided by other means, e.g. by a powerful spring.
A sleeve valve, also known as a ‘sliding sleeve valve’ and ‘sliding sleeve’, comprises a housing with radial ports and a sliding sleeve that can be shifted axially within the housing between an open position wherein the radial ports are exposed and a closed position where the sliding sleeve covers the ports. Due to their relatively simple design and operation, sleeve valves are widely used to control a radial flow into or out of a string within the wellbore.
In the following description and claims, the terms ‘normally open’ and ‘normally closed’ refer to the state of any valve, including sleeve valves, during run in. That is, a normally open valve is open during run in and activated to a closed state. Conversely, a normally closed valve is closed during run in and activated to an open state.
Known techniques for setting a packer or activating a sleeve valve include direct axial motion provided, for example, by a tool attached to a wireline, by a drop ball, by a downhole tractor or by the pressure within the central bore. Other techniques involve using fluid pressure to cause a rotation, e.g. for driving a leading screw to set a packer, or using a release mechanism as briefly described above.
In the following description and claims, the term ‘control’ implies a known response to an input. For example, a naïve control system could comprise a pressure sensor providing an input to an electronic controller running a feedback or feed forward algorithm, and providing a response, e.g. activating a valve. However, the known response implied by the above definition may also be provided by purely mechanical means. In particular, consider a bore valve with a flow plug and a complementary seat mounted coaxially with the central bore. In an open state, a spring maintains a distance, i.e. an annular restricted passage, between the flow plug and the seat. According to Bernoulli's principle, the increased velocity of an incompressible flow through the restricted passage causes a pressure drop. When this pressure drop applied to a working surface overcomes the spring force, the flow plug engages the seat such that the valve closes.
The packers and sleeve valve are usually separate units. In a pressure activated application, this means that a pressure operated valve must have an activation range that overlaps the activation range of a packer, and that the operational range must be kept within the overlap.
Some packers and valves depend on a chamber with air at atmospheric pressure. For example, shear pins or a radially biased lug may keep a sliding sleeve in a closed position during run in. The force required to break the shear pins or overcome the radial bias, can be achieved by a large pressure working on a small area, e.g. at the edge of the sleeve. This pressure can be approximately equal to the ambient pressure with a chamber at one bar. Some devices uses a burst disc, which breaks at a pressure significantly higher than the pressure in the ambient formation. As it would be expensive to design an entire system, including pumps and string, merely to release a sleeve, burst discs are mostly used in systems designed for high pressures anyway, e.g. systems for cementing, hydraulic fracturing and stimulation etc. There are numerous alternatives to burst disks. These alternatives typically require extensive sealing to maintain the integrity of the chamber during run in.
To illustrate some problems encountered by prior art, consider a well with several zones that need re-fracturing. The casing has deposits, e.g. scaling, that must be removed, for example by a swab cup or a milling tool. Traditionally, this requires a separate cleaning trip, i.e. running in and extracting a tool, e.g. attached to a wireline or string. After the cleaning trip, the casing is sufficiently clean for patching, i.e. to cover existing perforations to ensure that a fracturing fluid is injected at a sufficient pressure in one zone at a time. If the casing is not patched, the fracturing fluid and injection pressure is lost through numerous perforations and/or into severely fractured parts of the formation. Patching may be performed by several methods known in the art, e.g. by cementing a smaller diameter casing or liner within the old casing. Then, the well is re-fractured using the same techniques as those used for the original fracturing, e.g. starting from the bottom, firing perforation shots and injecting fracturing fluid, essentially water and sand, at a pressure sufficient to cause cracks in the formation and force the sand into the cracks to keep them open. The fracturing require flow rates above those available with coiled tubing, so a rig for handling joint pipes will be needed. In addition, perforation and fracturing may require separate trips. After fracturing a zone a plug is installed above the zone, and the process is repeated until all zones are re-fractured. The plugs must be removed before a production pipe is re-inserted into the well. This can be done by milling or drilling or unsetting a mechanical plug, and either once a zone is fractured or as a separate step at the end of the re-fracturing procedure. During the entire process, the pressure within the wellbore must be maintained. This includes handling sudden pressure increases or kicks.
A re-fracturing process as described is expensive and time consuming, in some cases even too costly for a given production field, so that a production field may be abandoned for economical rather than technical reasons. Thus there is a need for a less expensive process for re-fracturing. In general, there is a need to reduce the number of trips required for maintenance, and at the same time control sudden pressure pulses that may occur during re-fracturing, stimulation, water injection etc. in the oil- and gas industry, in geothermal applications etc.
A general objective of the present disclosure is to overcome at least one of the problems above while retaining the benefits of prior art. A more specific objective is to provide an improved service tool for performing fluid injection.